Drilling fluids used in the drilling of subterranean oil and gas wells along with other drilling fluid applications and drilling procedures are known. In rotary drilling there are a variety of functions and characteristics that are expected of drilling fluids, also known as drilling muds, or simply “muds”. The functions of a drilling fluid include, but are not necessarily limited to, cooling and lubricating the bit, lubricating the drill pipe, carrying the cuttings and other materials from the hole to the surface, and exerting a hydrostatic pressure against the borehole wall to prevent the flow of fluids from the surrounding formation into the borehole.
Drilling fluids are typically classified according to their base fluid. In water-based muds, solid particles are suspended in water or brine. Oil can be emulsified in the water which is the continuous phase. Brine-based drilling fluids, of course are a water-based mud (WBM) in which the aqueous component is brine. Oil-based muds (OBM) are the opposite or inverse. Solid particles are suspended in oil, and water or brine is emulsified in the oil and therefore the oil is the continuous phase. Oil-based muds can be either all-oil based or water-in-oil macroemulsions, which are also called invert emulsions. In oil-based mud, the oil may consist of any oil that may include, but is not limited to, diesel, mineral oil, esters, or alpha-olefins. OBMs as defined herein also include synthetic-based fluids or muds (SBMs) which are synthetically produced rather than refined from naturally-occurring materials. SBMs often include, but are not necessarily limited to, olefin oligomers of ethylene, esters made from vegetable fatty acids and alcohols, ethers and polyethers made from alcohols and polyalcohols, paraffinic, or aromatic, hydrocarbons alkyl benzenes, terpenes and other natural products and mixtures of these types. OBMs and SBMs are also sometimes collectively referred to as “non-aqueous fluids” (NAFs).
Damage to a reservoir is particularly harmful if it occurs while drilling through the pay zone or the zone believed to hold recoverable oil or gas. In order to avoid such damage, a different fluid—known as a “drill-in” fluid—may be pumped through the drill pipe while drilling through the pay zone.
Another type of fluid used in oil and gas wells is a completion fluid. A completion fluid is pumped down a well after drilling operations are completed and during the completion phase. Drilling mud typically is removed or displaced from the well using a completion fluid, which may be a clear brine. Then, the equipment required to produce fluids to the surface is installed in the well. A completion fluid must have sufficient density to maintain a differential pressure with the wellbore, which controls the well and to maintain the filter cake. The completion fluid must have sufficient viscosity and elasticity to maintain a suspension of bridging or weighting agents. The viscosity of a completion brine typically is maintained using polymers, such as starches, derivatized starches, gums, derivatized gums, and cellulosics. Unfortunately, although these polymers are water-soluble, they have a relatively low hydration rate in brines because very little water actually is available to hydrate the polymers in highly saline brines. Hydrating the polymers can be time consuming and expensive. Less time consuming and expensive methods for hydrating polymers in highly saline brines are greatly needed. Also needed are methods which will entirely eliminate the need to add these water soluble polymers to drilling and completion fluids. Formation damage often occurs when these polymers are removed from the wellbore, particularly if they have formed a filter cake on the wellbore that has infiltrated the adjacent formation.
Formation damage involves undesirable alteration of the initial characteristics of a producing formation, typically by exposure to drilling fluids. The water or solid particles in the drilling fluids, or both, tend to decrease the pore volume and effective permeability of the producible formation in the near-wellbore region. There may be at least three possible mechanisms at work. First, solid particles from the drilling fluid may physically plug or bridge across flowpaths in the porous formation. Second, when water contacts certain clay mineral in the formation, the clay typically swells, thus increasing in volume and in turn decreasing the pore volume. Third, chemical reactions between the drilling fluid and the formation rock and fluids may precipitate solids or semisolids that plug pore spaces.
Reduced hydrocarbon production can result from reservoir damage when a drilling mud deeply invades the subterranean reservoir. It will also be understood that the drilling fluid, e.g. oil-based mud, is deposited and concentrated at the borehole face and partially inside the formation. Many operators are interested in improving formation clean up and removing the cake or plugging material and/or improving formation damage after drilling into reservoirs with oil-based muds.
Limited hydrocarbon production may be increased by the creation of hydraulic fractures using fluids that transmit hydraulic pressure to the rock to induce fractures in the formation. Increased productivity through fractures is achieved by extending the area available for the hydrocarbon to flow to the well bore. Fractures are propped open by sand transported into the fracture during its creation by the fracturing fluid or by pumping high permeability proppant, relative to the formation permeability. When the applied pump rates and pressures are reduced or removed from the formation, closure of the fracture is prevented because the high permeability proppant maintains the fracture open. Fracturing fluids have been used for hydraulic fracturing since they maintain low formation-damage characteristics and have required rheological properties. However, fracturing fluids tend to have high fluid leakoff into the reservoir matrix which reduces the efficiency of the fluid during fracturing operations; therefore conventionally fluid loss agents have to be used for fracturing treatment.
It would be advantageous to improve the ability of drilling fluids, drill-in fluids, completion fluids and the like, to suspend solids while reducing or eliminating the presence of polymers to do the same. It would further be helpful to improve the fluid loss control of the fluids described, that is reduce, prevent or otherwise inhibit the unintentional and undesired loss of these fluids into a subterranean formation.
It would be desirable as well to provide a fluid that may be used as fracturing fluid without the addition of any fluid loss control agent. There is also a significant need for a lubricant fluid or lubricant additive for drilling fluids to reduce friction and increase lubricity. It would be as well desirable if compositions and methods could be devised to aid and improve the ability to clean up damage and difficulties caused to the wellbore and the formation. It may also be desirable to have a fluid with the capability of in-situ water shut-off by hydrating and swelling when contacting an aqueous phase, preventing water to flow.